In the recovery of oil from a rock reservoir generally only a fraction of the oil originally present is successfully extracted by primary recovery processes. In this case the oil reaches the surface as a result of the natural reservoir pressure. In secondary oil recovery, water is usually injected into one or more injection wells in the formation and the oil is driven to one or more production wells and then brought to the surface. This so-called water flooding as a secondary measure is relatively inexpensive and consequently is often used but in many cases leads to only a slight additional removal of oil from the reservoir.
An effective displacement of the oil, which is more expensive but in view of the future oil shortage is economically necessary, is successful by tertiary measures. This means processes in which either the viscosity of the oil is lowered and/or the viscosity of the reflooding water is increased and/or the interfacial tension between water and oil is lowered.
Most of these processes can be classified either as solution or mixture flooding, thermal oil recovery processes, surfactant or polymer flooding or as a combination of several of said processes.
Thermal recovery processes comprise the injection of steam or hot water or they occur as subsurface combustion. Solution or mixture processes involve the injection of a solvent for the oil into the reservoir, which solvent can be a gas and/or a liquid.
In surfactant processes a distinction is made, depending on the surfactant concentration, surfactant type and additives, between surfactant-supported water flooding (a process, which can serve, e.g., to increase the injectivity of injection wells or represent a "low-tension process"), micellar flooding and emulsion flooding. The surfactant process is based in the first place on a marked lowering of the interfacial tension between oil and flood water. In addition, the wettability of the rock surface and mobility ratio are very important. Favorable mobility ratios between oil and water are achieved by polymers.
This invention relates to a process for recovery of oil by surfactant flooding or micellar-polymer flooding in medium to high saline reservoirs.
The invention particularly relates to a process for reservoirs, which are governed by marked temperature fluctuations or a temperature gradient.
Since the temperature of the reservoir rock is basically determined by heat flow from the interior of the earth to the surface area, inconstant temperatures are caused either by sharp reservoir slopes or on an intervention in natural events. This intervention also occurs, e.g., the injection of water during water flooding. Long-lasting water flooding, especially of high-temperature reservoirs, often leads to the formation of a marked temperature gradient. This is particularly pronounced in the case of high-temperature offshore reservoirs, which are flooded with cold seawater, which leads to a marked cooling around the injection areas. Thus, e.g., in reservoirs in the North Sea area temperature spreads between about 10.degree. C. close to the injection sondes and about 100.degree. C. in more distant areas are known. A surfactant flooding process is, of course, ideally optimally effective in the entire temperature range. This ideal obviously assumes that the surfactant is stable for a long period under reservoir conditions.
Another problem of surfactant flooding is that many suitable surfactants, such as, e.g., alkyl or alkylaryl sulfonates, generally have a low tolerance limit in regard to the salinity of the reservoir water. The sensitivity of these surfactants to alkaline-earth ions is particularly pronounced. Many reservoir waters have high salinities; a very significant part of the North American light oil reservoirs have salinities around 100,000 ppm and higher, and the content of dissolved alkaline-earth ions in most cases is considerable. Also, the seawater often injected for secondary measures in offshore reservoirs has, with a TDS value of about 36,000 ppm and alkaline-earth ions of about 2,000 ppm, a salinity far above the compatibility limit for the usual sulfonates.
Typical surfactants, which are tolerant toward extremely high total salinities and corresponding alkaline-earth ion concentrations and can mobilize oil in a highly effective way, are, e.g., carboxymethylated oxethylates (cf. U.S. Pat. Nos. 4,478,281, 4,457,373 and 4,582,138). But these surfactants must be tailored for the conditions of the respective reservoir (salinity, oil character, temperature, etc.). Relatively insignificant deviations of the local reservoir temperature from a mean value has no marked influence on the surfactant activity. But marked temperature gradients with temperature spreads between 10.degree. to 100.degree. C. drastically impair surfactant effect.
On the other hand, if carboxymethylated oxethylates are combined with relatively hydrophobic alkyl, alkylaryl or dialkylaryl sulfonates, surfactant systems are obtained, which in the presence of suitable cosolvents can be effective in mobilizing oil over broad temperature ranges, e.g., between 10.degree. and 100.degree. C. This recently observed property can be understood to a certain extent, if the solubilities of the two surfactant groups are considered as a function of the temperature. The corresponding coefficients behave in a predominantly inverted manner, so that the surfactant activity is balanced to a certain extent over broad temperature ranges, as interfacial measurements as a function of temperature have shown in the meantime.